Systems and Methods for Artificial Lift Via a Downhole Positive Displacement Pump

ABSTRACT

Systems and methods for artificial lift via a downhole positive displacement pump are disclosed herein. The methods include methods of removing a wellbore liquid from a wellbore that extends within a subterranean formation and/or methods of locating the downhole positive displacement pump within the wellbore. The systems include hydrocarbon wells that include the wellbore, a casing, a rotary electric motor, the downhole positive displacement pump, and a liquid discharge conduit, and the systems may be utilized with and/or configured to perform the methods.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional No. 61/870,662,filed Aug. 27, 2013, the entirety of which is incorporated herein byreference for all purposes.

FIELD OF THE DISCLOSURE

The present disclosure is directed generally to systems and methods forartificial lift in a wellbore and more specifically to systems andmethods that utilize a downhole positive displacement pump to remove awellbore liquid from the wellbore.

BACKGROUND OF THE DISCLOSURE

A hydrocarbon well may be utilized to produce gaseous hydrocarbons froma subterranean formation. Often, a wellbore liquid may build up withinone or more portions of the hydrocarbon well. This wellbore liquid,which may include water, condensate, and/or liquid hydrocarbons, mayimpede flow of the gaseous hydrocarbons from the subterranean formationto a surface region via the hydrocarbon well, thereby reducing and/orcompletely blocking gaseous hydrocarbon production from the hydrocarbonwell.

Traditionally, plunger lift and/or rod pump systems have been utilizedto provide artificial lift and to remove this wellbore liquid from thehydrocarbon well. While these systems may be effective under certaincircumstances, they may not be capable of efficiently removing thewellbore liquid from long and/or deep hydrocarbon wells, fromhydrocarbon wells that include one or more deviated (or nonlinear)portions (or regions), and/or from hydrocarbon wells in which thegaseous hydrocarbons do not generate at least a threshold pressure.

As an illustrative, non-exclusive example, plunger lift systems requirethat the gaseous hydrocarbons develop at least the threshold pressure toprovide a motive force to convey a plunger between the subterraneanformation and the surface region. As another illustrative, non-exclusiveexample, rod pump systems utilize a mechanical linkage (i.e., a rod)that extends between the surface region and the subterranean formation;and, as the depth of the well (or length of the mechanical linkage) isincreased, the mechanical linkage becomes more prone to failure and/ormore prone to damage the casing. As yet another illustrative,non-exclusive example, neither plunger lift systems nor rod pump systemsmay be utilized effectively in wellbores that include deviated and/ornonlinear regions.

Improved hydrocarbon well drilling technologies permit an operator todrill a hydrocarbon well that extends for many thousands of meterswithin the subterranean formation, has a vertical depth of hundreds, oreven thousands, of meters, and/or that has a highly deviated wellbore.These improved drilling technologies are routinely utilized to drilllong and/or deep hydrocarbon wells that permit production of gaseoushydrocarbons from previously inaccessible subterranean formations.However, wellbore liquids cannot be removed efficiently from thesehydrocarbon wells using traditional artificial lift systems. Thus, thereexists a need for improved systems and methods for artificial lift toremove wellbore liquids from a hydrocarbon well.

SUMMARY OF THE DISCLOSURE

Systems and methods for artificial lift via a downhole positivedisplacement pump are disclosed herein. The methods may include methodsof removing a wellbore liquid from a wellbore that extends within asubterranean formation. These methods include electrically powering thedownhole positive displacement pump and pumping the wellbore liquid fromthe wellbore with the downhole positive displacement pump. The pumpingmay include pressurizing the wellbore liquid with the downhole positivedisplacement pump to generate a pressurized wellbore liquid at adischarge pressure and flowing the pressurized wellbore liquid at leasta threshold vertical distance to a surface region at a discharge flowrate of at least 0.75, and less than 16, cubic meters (approximately 5to approximately 100 barrels) per day.

In some embodiments, the pressurizing may include pressurizing to adischarge pressure of at least 25 MPa, continuously pumping the wellboreliquid from the wellbore, and/or pumping with at least a thresholdpumping efficiency of at least 50%. In some embodiments, the pumping mayinclude pumping with an axial piston pump and/or pumping with a radialpiston pump. In some embodiments, the electrically powering may includeelectrically powering with a rotary electric motor. In some embodiments,these methods further may include detecting a downhole processparameter. In some embodiments, these methods further may includecontrolling the discharge flow rate and/or the discharge pressure, suchas responsive at least in part to the detected process parameter. Insome embodiments, these methods further may include detecting a gas lockcondition of the downhole positive displacement pump and opening aliquid inlet valve of the downhole positive displacement pump responsiveto detecting the gas lock condition.

The methods also may include methods of locating (i.e., inserting and/orpositioning) the downhole positive displacement pump within thewellbore. These methods may include locating the downhole positivedisplacement pump within a casing conduit of a casing that extendswithin the wellbore by locating the downhole positive displacement pumpwithin a lubricator that is in selective fluid communication with thecasing conduit. These methods further may include conveying the downholepositive displacement pump through a nonlinear region of the casingconduit until the downhole positive displacement pump is located atleast a threshold vertical distance from the surface region.

In some embodiments, the conveying may include flowing the downholepositive displacement pump through the casing conduit with a fluid flow.In some embodiments, the downhole positive displacement pump and arotary electric motor together define a downhole assembly with a lengthof less than 10 meters. In some embodiments, the downhole positivedisplacement pump includes fewer than three stages.

The systems include hydrocarbon wells that include the wellbore, acasing, a rotary electric motor, the downhole positive displacementpump, and a liquid discharge conduit and may be utilized with and/orconfigured to perform the methods. In some embodiments, the downholepositive displacement pump may be located at least 1000 meters from asurface region and/or may be located downhole from a nonlinear region ofthe casing conduit. In some embodiments, the hydrocarbon well furtherincludes a controller that is programmed to control the operation of therotary electric motor and/or of the downhole positive displacement pump.In some embodiments, the hydrocarbon well includes a sensor that isconfigured to detect a downhole process parameter. In some embodiments,the controller is programmed or otherwise configured to control theoperation of the downhole positive displacement pump responsive, atleast in part, to the detected downhole process parameter.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic representation of illustrative, non-exclusiveexamples of a hydrocarbon well that may be utilized with and/or mayinclude the systems and methods according to the present disclosure.

FIG. 2 is a schematic block diagram of illustrative, non-exclusiveexamples of a downhole assembly according to the present disclosure thatincludes a rotary electric motor and a downhole positive displacementpump.

FIG. 3 is a schematic cross-sectional view of an illustrative,non-exclusive example of an axial piston pump that may be utilized withthe systems and methods according to the present disclosure.

FIG. 4 is a schematic cross-sectional view of an illustrative,non-exclusive example of a radial piston pump that may be utilized withthe systems and methods according to the present disclosure.

FIG. 5 is a fragmentary partial cross-sectional view of less schematicbut still illustrative, non-exclusive examples of a hydrocarbon wellthat includes a downhole assembly according to the present disclosure.

FIG. 6 is a fragmentary partial cross-sectional view of less schematicbut still illustrative, non-exclusive examples of another hydrocarbonwell that includes a downhole assembly according to the presentdisclosure.

FIG. 7 is a flowchart depicting methods according to the presentdisclosure of removing a wellbore liquid from a wellbore.

FIG. 8 is a flowchart depicting methods according to the presentdisclosure of locating a downhole positive displacement pump within awellbore.

DETAILED DESCRIPTION AND BEST MODE OF THE DISCLOSURE

FIGS. 1-6 provide illustrative, non-exclusive examples of hydrocarbonwells 10 according to the present disclosure and of downhole assemblies40 according to the present disclosure that may be utilized in and/orwith hydrocarbon wells 10. All elements may not be labeled in each ofFIGS. 1-6, but reference numerals associated therewith may be utilizedherein for consistency. Elements, components, and/or features that arediscussed herein with reference to one or more of FIGS. 1-6 may beincluded in and/or utilized with any of FIGS. 1-6 without departing fromthe scope of the present disclosure.

In general, elements that are likely to be included in a given (i.e., aparticular) embodiment are illustrated in solid lines, while elementsthat are optional to a given embodiment are illustrated in dashed lines.However, elements that are shown in solid lines are not essential to allembodiments, and an element shown in solid lines may be omitted from aparticular embodiment without departing from the scope of the presentdisclosure.

FIG. 1 is a schematic representation of illustrative, non-exclusiveexamples of a hydrocarbon well 10 that may be utilized with and/orinclude the systems and methods according to the present disclosure,while FIG. 2 is a schematic block diagram of illustrative, non-exclusiveexamples of a downhole assembly 40 according to the present disclosurethat includes a rotary electric motor 50 and a downhole positivedisplacement pump 60.

Hydrocarbon well 10 includes a wellbore 20 that extends between asurface region 12 and a subterranean formation 16 that is present withina subsurface region 14. The hydrocarbon well further includes a casing30 that extends within the wellbore and defines a casing conduit 32. Adownhole assembly 40, which includes a rotary electric motor 50 and adownhole positive displacement pump 60, is located within the casingconduit at least a threshold vertical distance 48 from surface region12. Threshold vertical distance 48 additionally or alternatively may bereferred to as threshold vertical depth 48. The downhole positivedisplacement pump is configured to be powered by the rotary electricmotor, such as to receive a wellbore liquid 22 and to pressurize thewellbore liquid to generate a pressurized wellbore liquid 24. A liquiddischarge conduit 80 extends between downhole positive displacement pump60 and surface region 12. The liquid discharge conduit is in fluidcommunication with casing conduit 32 via downhole positive displacementpump 60 and is configured to convey pressurized wellbore liquid 24 fromthe casing conduit, such as to surface region 12.

As illustrated in dashed lines in FIG. 1, hydrocarbon well 10 mayinclude a lubricator 28 that may be utilized to locate (i.e., insertand/or position) downhole assembly 40 within casing conduit 32 and/or toremove the downhole assembly from the casing conduit. In addition, andas illustrated in FIGS. 1-2, an injection conduit 38 may extend betweensurface region 12 and downhole assembly 40 and may be configured toinject a corrosion inhibitor and/or a scale inhibitor into casingconduit 32 and/or into fluid contact with downhole positive displacementpump 60, such as to decrease a potential for corrosion of and/or scalebuild-up within the downhole positive displacement pump.

As also illustrated in dashed lines, hydrocarbon well 10 and/or downholeassembly 40 further may include a sand control structure 44, which maybe configured to limit flow of sand into an inlet of positivedisplacement pump 60, and/or a gas control structure 46, which may limitflow of a wellbore gas 26 (as illustrated in FIG. 1) into downholepositive displacement pump 60. As further illustrated in dashed lines inFIG. 1, casing 30 may have a seat 34 attached thereto, with seat 34being configured to receive downhole assembly 40 and/or to retaindownhole assembly 40 at, or within, a desired region and/or locationwithin casing 30. Additionally or alternatively, downhole assembly 40may include and/or be operatively attached to a packer 42. Packer 42 maybe configured to swell or otherwise be expanded within casing conduit 32and to thereby retain downhole assembly 40 at, or within, the desiredregion and/or location within casing 30.

Returning to FIGS. 1-2, hydrocarbon well 10 and/or downhole assembly 40thereof further may include a power source 54 that is configured toprovide an electric current to rotary electric motor 50. In addition, asensor 92 may be configured to detect a downhole process parameter andmay be located within wellbore 20, may be operatively attached todownhole assembly 40, and/or may form a portion of the downholeassembly. The sensor may be configured to convey a data signal that isindicative of the process parameter to surface region 12 and/or may bein communication with a controller 90 that is configured to control theoperation of at least a portion of downhole assembly 40, such as bycontrolling rotary electric motor 50 and/or downhole positivedisplacement pump 60.

As discussed, downhole assembly 40 includes rotary electric motor 50 anddownhole positive displacement pump 60. Downhole assembly 40 further mayinclude a coupling 52 that is configured to transfer a mechanical poweroutput from rotary electric motor 50 to downhole positive displacementpump 60. Illustrative, non-exclusive examples of coupling 52 include anysuitable mechanical coupling, direct coupling, direct mechanicalcoupling, shaft, magnetic coupling, and/or flexible vibration dampener.As also discussed, rotary electric motor 50 may be powered by (orreceive electric current from) power source 54, which may be operativelyattached to downhole assembly 40, may form a portion of downholeassembly 40, and/or may be in electrical communication with downholeassembly 40 via an electrical conduit 56. Thus, downhole assembly 40according to the present disclosure may be configured to generatepressurized wellbore liquid 24 without utilizing a reciprocatingmechanical linkage that extends between surface region 12 and thedownhole assembly (such as might be utilized with traditional rod pumpsystems) to provide a motive force for operation of downhole positivedisplacement pump 60. This may permit downhole assembly 40 to beutilized in long, deep, and/or deviated wellbores where traditional rodpump systems may be ineffective, inefficient, and/or unable to generatethe pressurized wellbore liquid.

Similarly, and since downhole positive displacement pump 60 is poweredby rotary electric motor 50, downhole assembly 40 may be configured togenerate pressurized wellbore liquid 24 (and/or to remove thepressurized wellbore liquid from casing conduit 32 via liquid dischargeconduit 80) without requiring a threshold minimum pressure of wellboregas 26. This may permit downhole assembly 40 to be utilized inhydrocarbon wells 10 that do not develop sufficient gas pressure topermit utilization of traditional plunger lift systems and/or thatdefine long and/or deviated casing conduits 32 that preclude theefficient operation of traditional plunger lift systems.

Furthermore, and since downhole assembly 40 includes positivedisplacement pump 60, the downhole assembly may be sized, designed,and/or configured to generate pressurized wellbore liquid 24 at apressure that is sufficient to permit the pressurized wellbore liquid tobe conveyed via liquid discharge conduit 80 to surface region 12 withoututilizing a large number of pumping stages. It follows that reducing thenumber of pumping stages may decrease a length 41 of the downholeassembly (as illustrated in FIG. 1). As illustrative, non-exclusiveexamples, downhole assembly 40 may include fewer than five stages, fewerthan four stages, fewer than three stages, or a single stage.

As additional illustrative, non-exclusive examples, the length of thedownhole assembly may be less than 30 meters (m), less than 28 m, lessthan 26 m, less than 24 m, less than 22 m, less than 20 m, less than 18m, less than 16 m, less than 14 m, less than 12 m, less than 10 m, lessthan 8 m, less than 6 m, or less than 4 m. Additionally oralternatively, an outer diameter of the downhole assembly may be lessthan 20 centimeters (cm), less than 18 cm, less than 16 cm, less than 14cm, less than 12 cm, less than 10 cm, less than 9 cm, less than 8 cm,less than 7 cm, less than 6 cm, or less than 5 cm.

This (relatively) small length and/or (relatively) small diameter ofdownhole assemblies 40 according to the present disclosure may permitthe downhole assemblies to be located within and/or to flow throughand/or past deviated regions 33 within wellbore 20 and/or casing conduit32 that might obstruct and/or retain longer and/or larger-diameterdownhole assemblies that do not include rotary electric motor 50 anddownhole positive displacement pump 60 and/or that utilize a largernumber (such as more than 5, more than 6, more than 8, more than 10,more than 15, or more than 20) of stages to generate pressurizedwellbore liquid 24. Thus, downhole assemblies 40 according to thepresent disclosure may be operable in hydrocarbon wells 10 that areotherwise inaccessible to more traditional pumping technologies. Thismay include locating downhole assembly 40 uphole from deviated regions33, as schematically illustrated in dashed lines in FIG. 1, and/orlocating downhole assembly 40 downhole from deviated regions 33, such asin a horizontal portion of wellbore 20 and/or near a toe end 21 ofwellbore 20 (as schematically illustrated in dash-dot lines in FIG. 1).

Additionally or alternatively, the (relatively) small length and/or the(relatively) small diameter of downhole assemblies 40 according to thepresent disclosure may permit the downhole assemblies to be locatedwithin casing conduit 32 and/or be removed from casing conduit 32 vialubricator 28. This may permit the downhole assemblies to be locatedwithin the casing conduit without depressurizing hydrocarbon well 10,without killing well 10, without first supplying a kill weight fluid towellbore 20, and/or while containing wellbore fluids within thewellbore. This may increase an overall efficiency of downhole assemblies40 being inserted into and/or removed from wellbore 20, may decrease atime required to permit downhole assemblies 40 to be inserted intoand/or removed from wellbore 20, and/or may decrease a potential fordamage to hydrocarbon well 10 when downhole assemblies 40 are insertedinto and/or removed from wellbore 20.

Furthermore, and as discussed in more detail herein, downhole assemblies40 according to the present disclosure may be configured to generatepressurized wellbore liquid 24 at relatively low discharge flow ratesand/or at selectively variable discharge flow rates. This may permitdownhole assembly 40 to efficiently operate in low production ratehydrocarbon wells and/or in hydrocarbon wells that generate low volumesof wellbore liquid 22, in contrast to more traditional artificial liftsystems.

Downhole positive displacement pump 60 may include any suitable positivedisplacement pump that may be powered by rotary electric motor 50, mayreceive wellbore liquid 22, and/or may pressurize the wellbore liquid togenerate pressurized wellbore liquid 24. As illustrative, non-exclusiveexamples, downhole positive displacement pump 60 may include and/or be agear pump, a gerotor positive displacement pump, an internal gearpositive displacement pump, an external gear positive displacement pump,a screw pump, a triple screw positive displacement pump, a progressingcavity pump, a roots pump, a plunger pump, a piston pump, an axialpiston positive displacement pump, a linear angle plate positivedisplacement pump, a rotary vane positive displacement pump, and aradial piston positive displacement pump.

As a more specific but still illustrative, non-exclusive example, and asschematically illustrated in FIG. 3, downhole positive displacement pump60 may include an axial piston pump 100. The axial piston pump mayinclude a wobble plate 102 and a plurality of pistons 104 that areoperatively attached to and/or in mechanical communication with thewobble plate. The plurality of pistons may reciprocate along a pluralityof (substantially) parallel reciprocation axes 106. When downholepositive displacement pump 60 is located within wellbore 20, theplurality of parallel reciprocation axes may be (substantially) parallelto a longitudinal axis of wellbore 20. The wobble plate may be anadjustable angle wobble plate that is configured to change, vary, and/orregulate a distance that each of the plurality of pistons reciprocatesthrough changes in an angle 108 of the wobble plate relative to theplurality of reciprocation axes, thereby (selectively) changing adischarge flow rate of the downhole positive displacement pump. Aplurality of check valves 110 may regulate and/or restrict flow ofwellbore fluid 22 into the axial piston pump and/or flow of pressurizedwellbore fluid 24 out of the axial piston pump.

As another more specific but still illustrative, non-exclusive example,and as schematically illustrated in FIG. 4, downhole positivedisplacement pump 60 may include a radial piston pump 120. The radialpiston pump may include an eccentric shaft 122 and a plurality ofpistons 104 that are operatively attached to and/or in mechanicalcommunication with the eccentric shaft. The plurality of pistons maydefine a plurality of nonparallel reciprocation axes 124. When downholepositive displacement pump 60 is located within wellbore 20, theplurality of nonparallel reciprocation axes may be (substantially)perpendicular to the longitudinal axis of the wellbore. Similar to axialpiston pump 100, a plurality of check valves 110 may regulate and/orrestrict flow of wellbore fluid 22 into the axial piston pump and/orflow of pressurized wellbore fluid 24 out of the axial piston pump.

Returning to FIGS. 1-2, downhole positive displacement pump 60 furthermay include a liquid inlet valve 62. Liquid inlet valve 62 may beconfigured to selectively introduce wellbore liquid 22 into acompression chamber 64 of downhole positive displacement pump 60, asdiscussed in more detail herein.

Rotary electric motor 50 may include any suitable structure that isconfigured to power downhole positive displacement pump 60. Asillustrative, non-exclusive examples, rotary electric motor 50 mayinclude and/or be an AC rotary electric motor, a DC rotary electricmotor, and/or a variable speed rotary electric motor.

As discussed, wellbore 20 may define a deviated region 33, which alsomay be referred to herein as a nonlinear region 33, that may have adeviated (i.e., nonvertical) and/or nonlinear trajectory withinsubsurface region 14 and/or subterranean formation 16 thereof (asschematically illustrated in FIG. 1). In addition, and as alsodiscussed, downhole assembly 40, including rotary electric motor 50and/or downhole positive displacement pump 60, may be located downholefrom deviated region 33. As illustrative, non-exclusive examples,nonlinear region 33 may include and/or be a tortuous region, acurvilinear region, an L-shaped region, an S-shaped region, and/or atransition region between a (substantially) horizontal region and a(substantially) vertical region that may define a tortuous trajectory, acurvilinear trajectory, a deviated trajectory, an L-shaped trajectory,an S-shaped trajectory, and/or a transitional, or changing, trajectory.

Power source 54 may include any suitable structure that may beconfigured to provide the electric current to rotary electric motor 50and may be present in any suitable location. As an illustrative,non-exclusive example, power source 54 may be located in surface region12, and electrical conduit 56 may extend between the power source andthe rotary electric motor. Illustrative, non-exclusive examples ofelectrical conduit 56 include any suitable wire, cable, wireline, and/orworking line, and electrical conduit 56 may connect to rotary electricmotor 50 via any suitable electrical connection and/or wet-mateconnection.

As another illustrative, non-exclusive example, power source 54 mayinclude and/or be a battery pack. The battery pack may be located withinsurface region 12, may be located within wellbore 20, and/or may beoperatively and/or directly attached to downhole assembly 40 and/or torotary electric motor 50 thereof.

As additional illustrative, non-exclusive examples, power source 54 mayinclude and/or be a generator, an AC generator, a DC generator, aturbine, a solar-powered power source, a wind-powered power source,and/or a hydrocarbon-powered power source that may be located withinsurface region 12 and/or within wellbore 20. When power source 54 islocated within wellbore 20, the power source also may be referred toherein as a downhole power generation assembly 54.

Sensor 92 may include any suitable structure that is configured todetect the downhole process parameter. Illustrative, non-exclusiveexamples of the downhole process parameter include a downholetemperature, a downhole pressure, a discharge pressure from the downholepositive displacement pump, a downhole flow rate, and/or a dischargeflow rate from the downhole positive displacement pump.

It is within the scope of the present disclosure that sensor 92 may beconfigured to detect the downhole process parameter at any suitablelocation within wellbore 20. As an illustrative, non-exclusive example,the sensor may be located such that the downhole process parameter isindicative of a condition at an inlet to downhole positive displacementpump 60. As another illustrative, non-exclusive example, the sensor maybe located such that the downhole process parameter is indicative of acondition at an outlet from downhole positive displacement pump 60.

When hydrocarbon well 10 includes sensor 92, the hydrocarbon well alsomay include a data communication conduit 94 (as illustrated in FIG. 1)that may be configured to convey a signal that is indicative of thedownhole process parameter between sensor 92 and surface region 12. Asan illustrative, non-exclusive example, controller 90 may be locatedwithin surface region 12, and data communication conduit 94 may conveythe signal to the controller. As another illustrative, non-exclusiveexample, the data communication conduit may convey the signal to adisplay and/or to a terminal that is located within surface region 12.

Controller 90 may include any suitable structure that may be configuredto control the operation of any suitable portion of hydrocarbon well 10,such as downhole assembly 40, rotary electric motor 50, and/or downholepositive displacement pump 60. This may include controlling usingmethods 200 and/or methods 300, which are discussed in more detailherein.

As illustrated in FIG. 1, controller 90 may be located in any suitableportion of hydrocarbon well 10. As an illustrative, non-exclusiveexample, the controller may include and/or be an autonomous and/orautomatic controller that is located within wellbore 20 and/or that isdirectly and/or operatively attached to downhole assembly 40, to rotaryelectric motor 50, and/or to downhole positive displacement pump 60.Thus, controller 90 may be configured to control the operation ofdownhole assembly 40 without requiring that a data signal be conveyed tosurface region 12 via data communication conduit 94. Additionally oralternatively, controller 90 may be located within surface region 12 andmay communicate with downhole assembly 40 via data communication conduit94.

As an illustrative, non-exclusive example, controller 90 may beprogrammed to maintain a target wellbore liquid level within wellbore 20above downhole positive displacement pump 60. This may includeincreasing a discharge flow rate of pressurized wellbore liquid 24 thatis generated by the downhole positive displacement pump to decrease thewellbore liquid level and/or decreasing the discharge flow rate toincrease the wellbore liquid level.

As another illustrative, non-exclusive example, controller 90 may beprogrammed to regulate the discharge flow rate to control the dischargepressure from the downhole positive displacement pump. This may includeincreasing the discharge flow rate to increase the discharge pressureand/or decreasing the discharge flow rate to decrease the dischargepressure.

As a more specific but still illustrative, non-exclusive example, andwhen hydrocarbon well 10 includes sensor 92, controller 90 may beprogrammed to control a rotational frequency of rotary electric motor 50based, at least in part, on the downhole process parameter. This mayinclude increasing the rotational frequency to increase the dischargeflow rate and/or decreasing the rotational frequency to decrease thedischarge flow rate.

As another more specific but still illustrative, non-exclusive example,and when downhole positive displacement pump 60 includes the axialpiston pump, controller 90 may be programmed to control the angle of thewobble plate based, at least in part, on the downhole process parameter.This may include changing the angle to increase and/or decrease thedischarge flow rate.

As yet another more specific but still illustrative, non-exclusiveexample and when downhole positive displacement pump 60 includes a gearpump, controller 90 may be programmed to control a spacing between gearsof the gear pump based, at least in part, on the downhole processparameter. This may include increasing the spacing to decrease thedischarge flow rate and/or decreasing the spacing to increase thedischarge flow rate.

As another more specific but still illustrative, non-exclusive example,and when downhole positive displacement pump 60 includes liquid inletvalve 62, controller 90 may be programmed to control the operation ofthe liquid inlet valve. This may include opening the liquid inlet valveto permit wellbore fluid to enter compression chamber 64 of the downholepositive displacement pump responsive to the downhole process parameterindicating a gas lock condition of the downhole positive displacementpump.

As discussed, downhole assembly 40 according to the present disclosuremay be utilized to provide artificial lift in wellbores that define alarge vertical distance, or depth, 48, in wellbores that define a largeoverall length, and/or in wellbores in which downhole assembly 40 islocated at least a threshold vertical distance from surface region 12.As illustrative, non-exclusive examples, the vertical depth of wellbore20, the overall length of wellbore 20, and/or the threshold verticaldistance of downhole assembly 40 from surface region 12 may be at least250 meters (m), at least 500 m, at least 750 m, at least 1000 m, atleast 1250 m, at least 1500 m, at least 1750 m, at least 2000 m, atleast 2250 m, at least 2500 m, at least 2750 m, at least 3000 m, atleast 3250 m, and/or at least 3500 m. Additionally or alternatively, thevertical depth of wellbore 20, the overall length of wellbore 20, and/orthe threshold vertical distance of downhole assembly 40 from surfaceregion 12 may be less than 8000 m, less than 7750 m, less than 7500 m,less than 7250 m, less than 7000 m, less than 6750 m, less than 6500 m,less than 6250 m, less than 6000 m, less than 5750 m, less than 5500 m,less than 5250 m, less than 5000 m, less than 4750 m, less than 4500 m,less than 4250 m, and/or less than 4000 m. Further additionally oralternatively, the vertical depth of wellbore 20, the overall length ofwellbore 20, and/or the threshold vertical distance of downhole assembly40 from surface region 12 may be in a range defined, or bounded, by anycombination of the preceding maximum and minimum depths.

FIG. 5 provides less schematic but still illustrative, non-exclusiveexamples of a hydrocarbon well 10 that includes a downhole assembly 40according to the present disclosure. In FIG. 5, downhole assembly 40 islocated within a casing conduit 32 that is defined by a casing 30.Casing 30 includes a plurality of perforations 36 that provide fluidcommunication between casing conduit 32 and a subterranean formation 16.Downhole assembly 40 is retained within a liquid discharge conduit 80 bya seat 34 and/or by a packer 42 and is configured to receive wellboreliquid 22 from casing conduit 32 and to generate pressurized wellboreliquid 24 therefrom.

As illustrated in FIG. 5, wellbore gas 26 may flow within an annularspace that is defined within casing conduit 32 between casing 30 and atubing 78 that defines liquid discharge conduit 80. As also illustratedin FIG. 5, a plurality of sensors 92 may detect a plurality of downholeprocess parameters at an inlet 66 to downhole positive displacement pump60 and/or at an outlet 67 from the downhole positive displacement pump.

FIG. 6 provides less schematic but still illustrative, non-exclusiveexamples of another hydrocarbon well 10 that includes a downholeassembly 40 according to the present disclosure that includes a downholepositive displacement pump 60 and a rotary electric motor 50. In FIG. 6,downhole assembly 40 is retained within a liquid discharge conduit 80 bya seat 34 and/or by a packer 42. Downhole positive displacement pump 60receives a wellbore liquid 22 via an inlet 66 thereof, pressurizes thewellbore liquid to generate a pressurized wellbore liquid 24, anddischarges the pressurized wellbore liquid from an outlet 67 in the formof an outlet valve 68.

Downhole assembly 40 of FIG. 6 further may include and/or be utilizedwith additional features and/or structures, such as those that arediscussed in more detail herein. As illustrative, non-exclusiveexamples, and as illustrated in FIG. 6, downhole assembly 40 may includea controller 90 and/or sensors 92, and sensors 92 may be located nearand/or associated with inlet 66 and/or outlet 67.

As another illustrative, non-exclusive example, a coupler 52 mayoperatively connect downhole positive displacement pump 60 and rotaryelectric motor 50. As yet another illustrative, non-exclusive example, agas control structure 46 may restrict flow of a wellbore gas intodownhole positive displacement pump 60. As another illustrative,non-exclusive example, an electrical conduit 56 and/or a datacommunication conduit 94 may be in electrical communication withdownhole assembly 40, may extend within casing conduit 32, and/or mayextend within liquid discharge conduit 80.

FIG. 7 is a flowchart depicting methods 200 according to the presentdisclosure of removing a wellbore liquid from a wellbore that extendswithin a subterranean formation. Methods 200 may include detecting adownhole process parameter at 210 and include electrically powering adownhole positive displacement pump at 220 and pumping the wellboreliquid from the wellbore at 230. Methods 200 further may includeproducing a hydrocarbon gas at 240, controlling the operation of adownhole assembly at 250, injecting a supplemental material into thewellbore at 260, restricting sand flow into the downhole positivedisplacement pump at 270, and/or restricting hydrocarbon gas flow intothe downhole positive displacement pump at 280.

Detecting the downhole process parameter at 210 may include detectingany suitable downhole process parameter that is indicative of anysuitable condition within the wellbore. As illustrative, non-exclusiveexamples, the downhole process parameter may be collected at, or near,an inlet to the downhole positive displacement pump, may be indicativeof a condition at, or near, the inlet to the downhole positivedisplacement pump, may be collected at, or near, an outlet from thedownhole positive displacement pump, and/or may be indicative of acondition at, or near, the outlet from the positive displacement pump.Illustrative, non-exclusive examples of the downhole process parameterare discussed herein. When methods 200 include the detecting at 210,methods 200 further may include communicating the downhole processparameter to a surface region and/or utilizing the downhole processparameter to control the operation of the downhole assembly. This mayinclude controlling the operation of the downhole positive displacementpump and/or of a rotary electric motor that is configured to power thedownhole positive displacement pump, as discussed herein.

Electrically powering the downhole positive displacement pump at 220 mayinclude electrically powering the downhole positive displacement pumpwith the rotary electric motor, such as via any suitable couplingbetween the downhole positive displacement pump and the rotary electricmotor. The electrically powering at 220 may include conveying anelectric current from the surface region to the rotary electric motor,such as via an electrical conduit, and providing the electric current tothe rotary electric motor. Additionally or alternatively, theelectrically powering at 220 also may include generating the electriccurrent within the wellbore and conveying the electric current to therotary electric motor. Illustrative, non-exclusive examples of therotary electric motor, the electrical conduit, and/or the coupling arediscussed herein.

Pumping the wellbore liquid from the wellbore at 230 may include pumpingthe wellbore liquid from the wellbore with the downhole positivedisplacement pump. This may include pressurizing, at 232, the wellboreliquid within the downhole positive displacement pump to generate apressurized wellbore liquid at a discharge pressure and/or flowing, at234, the pressurized wellbore liquid at least a threshold verticaldistance to the surface region at a discharge flow rate.

The pumping at 230 may include at least substantially continuouslypumping the wellbore liquid from the wellbore and/or pumping thepressurized wellbore liquid through a liquid discharge conduit thatextends within the wellbore and/or between the downhole positivedisplacement pump and the surface region. Illustrative, non-exclusiveexamples of the discharge pressure include discharge pressures of atleast 20 megapascals (MPa), at least 25 MPa, at least 30 MPa, at least35 MPa, at least 40 MPa, at least 45 MPa, at least 50 MPa, at least 55MPa, at least 60 MPa, at least 65 MPa, and/or at least 70 MPa.Additionally or alternatively, the discharge pressure also may be lessthan 100 MPa, less than 95 MPa, less than 80 MPa, less than 75 MPa, lessthan 70 MPa, less than 65 MPa, less than 60 MPa, less than 55 MPa,and/or less than 50 MPa. Further additionally or alternatively, thedischarge pressure may be in a range bounded by any combination of thepreceding minimum and maximum discharge pressures.

The discharge pressure (in kilopascals) also may be at least a thresholdmultiple of the threshold vertical distance (in meters). Illustrative,non-exclusive examples of the threshold multiple include thresholdmultiples of at least 5, at least 6, at least 7, at least 8, at least 9,at least 10, at least 11, and/or at least 12.

Illustrative, non-exclusive examples of the discharge flow rate includedischarge flow rates of at least 0.5, at least 0.75, at least 1, atleast 2, at least 3, at least 4, at least 5, at least 6, at least 7, atleast 8, at least 9, at least 10, at least 12, at least 14, at least 16,at least 18, at least 20, at least 22, at least 24, at least 26, atleast 28, and/or at least 30 cubic meters per day. Additionally oralternatively, the discharge flow rate also may be less than 40, lessthan 38, less than 36, less than 34, less than 32, less than 30, lessthan 28, less than 26, less than 24, less than 22, less than 20, lessthan 18, less than 16, less than 14, less than 12, less than 10, lessthan 9, less than 8, less than 7, less than 6, less than 5, less than 4,less than 3, less than 2, and/or less than 1 cubic meters per day.Further additionally or alternatively, the discharge flow rate may be ina range bounded by any combination of the preceding minimum and maximumdischarge flow rates.

The pumping at 230 further may include pumping with at least a thresholdpumping efficiency. Illustrative, non-exclusive examples of thethreshold pumping efficiency include threshold pumping efficiencies ofat least 50%, at least 55%, at least 60%, at least 65%, at least 70%, atleast 75%, and/or at least 80%.

As a more specific but still illustrative, non-exclusive example, thepumping at 230 also may include pumping with an axial piston pump. Thismay include rotating a wobble plate to reciprocate a plurality ofpistons that is associated with the axial piston pump. The plurality ofpistons may reciprocate along a respective plurality of (substantially)parallel reciprocation axes that may be (substantially) parallel to alongitudinal axis of the wellbore. Additionally or alternatively, thisalso may include changing an angle of the wobble plate relative to theplurality of pistons to change the discharge flow rate of the downholepositive displacement pump.

As another more specific but still illustrative, non-exclusive example,the pumping at 230 also may include pumping with a radial piston pump.This may include rotating an eccentric shaft to reciprocate a pluralityof pistons that is associated with the radial piston pump and/orreciprocating the plurality of pistons along a respective plurality ofnonparallel reciprocation axes.

Producing the hydrocarbon gas at 240 may include producing thehydrocarbon gas from the subterranean formation and may be performed atleast partially concurrently with the pumping at 230. As anillustrative, non-exclusive example, the producing at 240 may includeproducing through a gas discharge conduit that extends within thewellbore and/or between the subterranean formation and the surfaceregion.

Controlling the operation of the downhole assembly at 250 may includecontrolling the operation of any suitable portion of the downholeassembly, and it is within the scope of the present disclosure that thecontrolling at 250 may be accomplished in any suitable manner. Asillustrative, non-exclusive examples, the controlling at 250 may includeautomatically controlling, autonomously controlling, controlling with acontroller that is located within the wellbore, controlling with acontroller that is directly attached to the downhole assembly and/or tothe downhole positive displacement pump, and/or controlling withoutrequiring that a data signal be conveyed between the downhole assemblyand the surface region.

As illustrative, non-exclusive examples, the controlling at 250 mayinclude controlling the discharge flow rate and/or the dischargepressure from the downhole positive displacement pump. As additionalillustrative, non-exclusive examples, and as discussed herein, thecontrolling at 250 also may include regulating a rotational frequency ofthe rotary electric motor, regulating a spacing between gears of a gearpump that comprises the downhole positive displacement pump, and/orregulating an angle of a wobble plate of an axial piston pump thatcomprises the downhole positive displacement pump.

As a more specific but still illustrative, non-exclusive example, thecontrolling at 250 also may include maintaining a target wellbore liquidlevel within the wellbore above the downhole positive displacement pump(or an inlet thereof), such as to prevent (or decrease a potential for)a gas lock condition within the downhole positive displacement pump. Asanother more specific but still illustrative, non-exclusive example, thedetecting at 210 may include monitoring the discharge pressure from thedownhole positive displacement pump, and the controlling at 250 mayinclude regulating the discharge flow rate to control the dischargepressure. This may include increasing the discharge flow rate toincrease the discharge pressure and/or decreasing the discharge flowrate to decrease the discharge pressure.

As yet another more specific but still illustrative, non-exclusiveexample, the downhole positive displacement pump may include a liquidinlet valve that is configured to selectively introduce the wellboreliquid into a compression chamber of the downhole positive displacementpump. Under these conditions, the detecting at 210 may include detectinga gas lock condition of the downhole positive displacement pump, and thecontrolling at 250 may include opening the liquid inlet valve responsiveto detecting the gas lock condition.

Injecting the supplemental material into the wellbore at 260 may includeinjecting any suitable supplemental material into any suitable portionof the wellbore. As an illustrative, non-exclusive example, theinjecting at 260 may include injecting a corrosion inhibitor and/or ascale inhibitor into the wellbore, such as to decrease a potential forcorrosion of and/or scale buildup within the downhole positivedisplacement pump and/or to increase a service life of the downholepositive displacement pump. As another illustrative, non-exclusiveexample, the injecting at 260 also may include injecting downhole fromthe downhole positive displacement pump, injecting into the downholepositive displacement pump, and/or injecting such that the supplementalmaterial flows through the downhole positive displacement pump with thewellbore liquid.

Restricting sand flow into the downhole positive displacement pump at270 may include restricting using any suitable structure. As anillustrative, non-exclusive example, the restricting at 270 may includerestricting with a sand filter. Similarly, restricting hydrocarbon gasflow into the downhole positive displacement pump at 280 may includerestricting using any suitable structure. As an illustrative,non-exclusive example, the restricting at 280 may include restrictingwith a gas-liquid separation assembly that is located upstream from,that is operatively attached to, and/or that forms a portion of thedownhole positive displacement pump.

FIG. 8 is a flowchart depicting methods 300 according to the presentdisclosure of locating a downhole positive displacement pump within awellbore that extends within a subterranean formation. Methods 300include locating the downhole positive displacement pump within a casingconduit at 310 and conveying the downhole positive displacement pumpthrough the casing conduit at 320. Methods 300 further may includeretaining the downhole positive displacement pump at a desired locationwithin the casing conduit at 330, coupling the downhole positivedisplacement pump with a power source at 340, and/or producing awellbore liquid from the wellbore at 350. The downhole positivedisplacement pump may form a portion of and/or may be operativelyattached to a downhole assembly that includes the downhole positivedisplacement pump and a rotary electric motor, and methods 300 may beperformed with, or on, the downhole assembly.

Locating the downhole positive displacement pump within the casingconduit at 310 may include locating the downhole positive displacementpump in any suitable casing conduit that may be defined by a casing thatextends within the wellbore. As an illustrative, non-exclusive example,the locating at 310 may include placing the downhole positivedisplacement pump within a lubricator that is in selective fluidcommunication with the casing conduit and/or transferring the downholepositive displacement pump from the lubricator to the casing conduit. Asanother illustrative, non-exclusive example, the locating at 310 alsomay include locating without first killing a hydrocarbon well thatincludes the wellbore, locating without supplying a kill weight fluid tothe wellbore, locating while containing (all) wellbore fluids within thewellbore, and/or locating without depressurizing (or completelydepressurizing) the wellbore (or at least a portion of the wellbore thatis proximal to the surface region).

Conveying the downhole positive displacement pump through the casingconduit at 320 may include conveying until the downhole positivedisplacement pump is at least a threshold vertical distance from thesurface region. Illustrative, non-exclusive examples of the thresholdvertical distance are disclosed herein.

It is within the scope of the present disclosure that the casing conduitmay define a nonlinear trajectory and/or a nonlinear region and that theconveying at 320 may include conveying along the nonlinear trajectory,through the nonlinear region, and/or past the nonlinear region.Illustrative, non-exclusive examples of the nonlinear region and/or thenonlinear trajectory are discussed herein.

The conveying may be accomplished in any suitable manner. As anillustrative, non-exclusive example, the conveying may includeestablishing a fluid flow from the surface region, through the casingconduit, and into the subterranean formation; and the conveying at 320may include flowing the downhole positive displacement pump through thecasing conduit with the fluid flow. As additional illustrative,non-exclusive examples, the conveying at 320 also may include conveyingon a wireline, conveying with coiled tubing, conveying with rods, and/orconveying with a tractor.

Retaining the downhole positive displacement pump at the desiredlocation within the casing conduit at 330 may include retaining thedownhole positive displacement pump in any suitable manner. As anillustrative, non-exclusive example, the retaining at 330 may includeswelling a packer that is operatively attached to the downhole positivedisplacement pump to retain the downhole positive displacement pump atthe desired location. As another illustrative, non-exclusive example,the retaining at 330 also may include locating the downhole positivedisplacement pump on a seat that is present within the casing conduitand that is configured to receive and/or to retain the downhole positivedisplacement pump.

Coupling the downhole positive displacement pump with the power sourceat 340 may include coupling the downhole positive displacement pump withthe power source subsequent to the conveying at 320. Illustrative,non-exclusive examples of the power source are disclosed herein.

Producing the wellbore liquid from the wellbore at 350 may includeproducing the wellbore liquid with the downhole positive displacementpump and may be accomplished in any suitable manner. As an illustrative,non-exclusive example, the producing at 350 may be at leastsubstantially similar to the pumping at 230, which is discussed in moredetail herein.

In the present disclosure, several of the illustrative, non-exclusiveexamples have been discussed and/or presented in the context of flowdiagrams, or flow charts, in which the methods are shown and describedas a series of blocks, or steps. Unless specifically set forth in theaccompanying description, it is within the scope of the presentdisclosure that the order of the blocks may vary from the illustratedorder in the flow diagram, including with two or more of the blocks (orsteps) occurring in a different order and/or concurrently. It is alsowithin the scope of the present disclosure that the blocks, or steps,may be implemented as logic, which also may be described as implementingthe blocks, or steps, as logics. In some applications, the blocks, orsteps, may represent expressions and/or actions to be performed byfunctionally equivalent circuits or other logic devices. The illustratedblocks may, but are not required to, represent executable instructionsthat cause a computer, processor, and/or other logic device to respond,to perform an action, to change states, to generate an output ordisplay, and/or to make decisions.

As used herein, the term “and/or” placed between a first entity and asecond entity means one of (1) the first entity, (2) the second entity,and (3) the first entity and the second entity. Multiple entities listedwith “and/or” should be construed in the same manner, i.e., “one ormore” of the entities so conjoined. Other entities may optionally bepresent other than the entities specifically identified by the “and/or”clause, whether related or unrelated to those entities specificallyidentified. Thus, as a non-limiting example, a reference to “A and/orB,” when used in conjunction with open-ended language such as“comprising” may refer, in one embodiment, to A only (optionallyincluding entities other than B); in another embodiment, to B only(optionally including entities other than A); in yet another embodiment,to both A and B (optionally including other entities). These entitiesmay refer to elements, actions, structures, steps, operations, values,and the like.

As used herein, the phrase “at least one,” in reference to a list of oneor more entities should be understood to mean at least one entityselected from any one or more of the entity in the list of entities, butnot necessarily including at least one of each and every entityspecifically listed within the list of entities and not excluding anycombinations of entities in the list of entities. This definition alsoallows that entities may optionally be present other than the entitiesspecifically identified within the list of entities to which the phrase“at least one” refers, whether related or unrelated to those entitiesspecifically identified. Thus, as a non-limiting example, “at least oneof A and B” (or, equivalently, “at least one of A or B,” or,equivalently “at least one of A and/or B”) may refer, in one embodiment,to at least one, optionally including more than one, A, with no Bpresent (and optionally including entities other than B); in anotherembodiment, to at least one, optionally including more than one, B, withno A present (and optionally including entities other than A); in yetanother embodiment, to at least one, optionally including more than one,A, and at least one, optionally including more than one, B (andoptionally including other entities). In other words, the phrases “atleast one,” “one or more,” and “and/or” are open-ended expressions thatare both conjunctive and disjunctive in operation. For example, each ofthe expressions “at least one of A, B and C,” “at least one of A, B, orC,” “one or more of A, B, and C,” “one or more of A, B, or C” and “A, B,and/or C” may mean A alone, B alone, C alone, A and B together, A and Ctogether, B and C together, A, B and C together, and optionally any ofthe above in combination with at least one other entity.

In the event that any patents, patent applications, or other referencesare incorporated by reference herein and (1) define a term in a mannerthat is inconsistent with and/or (2) are otherwise inconsistent with,either the non-incorporated portion of the present disclosure or any ofthe other incorporated references, the non-incorporated portion of thepresent disclosure shall control, and the term or incorporateddisclosure therein shall only control with respect to the reference inwhich the term is defined and/or the incorporated disclosure was presentoriginally.

As used herein the terms “adapted” and “configured” mean that theelement, component, or other subject matter is designed and/or intendedto perform a given function. Thus, the use of the terms “adapted” and“configured” should not be construed to mean that a given element,component, or other subject matter is simply “capable of” performing agiven function but that the element, component, and/or other subjectmatter is specifically selected, created, implemented, utilized,programmed, and/or designed for the purpose of performing the function.It is also within the scope of the present disclosure that elements,components, and/or other recited subject matter that is recited as beingadapted to perform a particular function may additionally oralternatively be described as being configured to perform that function,and vice versa.

INDUSTRIAL APPLICABILITY

The systems and methods disclosed herein are applicable to the oil andgas industry.

It is believed that the disclosure set forth above encompasses multipledistinct inventions with independent utility. While each of theseinventions has been disclosed in its preferred form, the specificembodiments thereof as disclosed and illustrated herein are not to beconsidered in a limiting sense as numerous variations are possible. Thesubject matter of the inventions includes all novel and non-obviouscombinations and subcombinations of the various elements, features,functions and/or properties disclosed herein. Similarly, where theclaims recite “a” or “a first” element or the equivalent thereof, suchclaims should be understood to include incorporation of one or more suchelements, neither requiring nor excluding two or more such elements.

1. A method of removing a wellbore liquid from a wellbore that extendswithin a subterranean formation, the method comprising: electricallypowering a downhole positive displacement pump; and pumping the wellboreliquid from the wellbore with the downhole positive displacement pump,wherein the pumping includes: (i) pressurizing the wellbore liquid withthe downhole positive displacement pump to generate a pressurizedwellbore liquid at a discharge pressure; and (ii) flowing thepressurized wellbore liquid at least a threshold vertical distance to asurface region at a discharge flow rate of at least 0.75 cubic metersper day and less than 16 cubic meters per day.
 2. The method of claim 1,wherein the discharge pressure is at least 25 MPa.
 3. The method ofclaim 1, wherein the pumping includes continuously pumping the wellboreliquid from the wellbore.
 4. The method of claim 1, wherein the methodfurther includes producing a hydrocarbon gas from the subterraneanformation at least partially concurrently with the pumping.
 5. Themethod of claim 1, wherein the pumping includes pumping with at least athreshold pumping efficiency of at least 50%.
 6. The method of claim 1,wherein the pumping includes pumping with an axial piston pump.
 7. Themethod of claim 1, wherein the pumping includes pumping with a radialpiston pump.
 8. The method of claim 1, wherein the electrically poweringincludes electrically powering with a rotary electric motor.
 9. Themethod of claim 8, wherein the electrically powering includes generatingan electric current within the wellbore and conveying the electriccurrent to the rotary electric motor.
 10. The method of claim 1, whereinthe method further includes detecting a downhole process parameter. 11.The method of claim 10, wherein the downhole process parameter includesat least one of a downhole temperature, a downhole pressure, thedischarge pressure, a downhole flow rate, and the discharge flow rate.12. The method of claim 1, wherein the method further includescontrolling at least one of the discharge flow rate and the dischargepressure.
 13. The method of claim 12, wherein the controlling includesregulating a rotational frequency of a rotary electric motor.
 14. Themethod of claim 12, wherein the method includes monitoring the dischargepressure, wherein the controlling includes regulating the discharge flowrate to control the discharge pressure, and further wherein thecontrolling includes at least one of: (i) increasing the discharge flowrate to increase the discharge pressure; and (ii) decreasing thedischarge flow rate to decrease the discharge pressure.
 15. The methodof claim 1, wherein the downhole positive displacement pump includes aliquid inlet valve that is configured to selectively introduce thewellbore liquid into a compression chamber of the downhole positivedisplacement pump, wherein the method includes detecting a gas lockcondition of the downhole positive displacement pump, and furtherwherein the method includes opening the liquid inlet valve responsive todetecting the gas lock condition.
 16. The method of claim 1, wherein thethreshold vertical distance is at least 1000 meters.
 17. The method ofclaim 1, wherein the downhole positive displacement pump and a rotaryelectric motor together define a downhole assembly, and further whereina length of the downhole assembly is less than 10 meters.
 18. The methodof claim 1, wherein the downhole positive displacement pump includesfewer than three stages.
 19. A method of locating a downhole positivedisplacement pump within a wellbore that extends within a subterraneanformation, the method comprising: locating the downhole positivedisplacement pump within a casing conduit of a casing that extendswithin the wellbore, wherein the locating includes placing the downholepositive displacement pump within a lubricator that is in selectivefluid communication with the casing conduit; and conveying the downholepositive displacement pump through the casing conduit until the downholepositive displacement pump is at least a threshold vertical distancefrom a surface region, wherein the casing conduit defines a nonlinearregion, and further wherein the conveying includes conveying through thenonlinear region.
 20. The method of claim 19, wherein the nonlinearregion includes at least one of a tortuous region, a curvilinear region,a deviated region, an L-shaped region, an S-shaped region, and atransition region between a horizontal region and a vertical region. 21.The method of claim 19, wherein the conveying includes at least one ofconveying without first supplying a kill weight fluid to the wellboreand conveying while containing wellbore fluids within the wellbore. 22.The method of claim 19, wherein the conveying includes establishing afluid flow from the surface region, through the casing conduit, and intothe subterranean formation, and flowing the downhole positivedisplacement pump through the casing conduit with the fluid flow. 23.The method of claim 19, wherein the threshold vertical distance is atleast 1000 meters.
 24. The method of claim 19, wherein the downholepositive displacement pump and a rotary electric motor together define adownhole assembly, and further wherein a length of the downhole assemblyis less than 10 meters.
 25. The method of claim 19, wherein the downholepositive displacement pump includes fewer than three stages.
 26. Ahydrocarbon well, comprising: a wellbore that extends between a surfaceregion and a subterranean formation; a casing that extends within thewellbore and defines a casing conduit; a rotary electric motor that islocated within the casing conduit; a downhole positive displacement pumpthat is configured to be powered by the rotary electric motor, whereinthe downhole positive displacement pump is located within the wellboreat least a threshold vertical distance from the surface region, whereinthe downhole positive displacement pump and the rotary electric motortogether define a downhole assembly, and further wherein a length of thedownhole assembly is less than 10 meters; and a liquid discharge conduitthat extends between the downhole positive displacement pump and thesurface region and is in fluid communication with the casing conduit viathe downhole positive displacement pump, wherein the downhole positivedisplacement pump is configured to convey a wellbore liquid from thecasing conduit via the liquid discharge conduit; and wherein at leastone of: (i) the threshold vertical distance is at least 1000 meters; and(ii) the casing conduit defines a nonlinear region and the downholeassembly is located downhole from the nonlinear region.
 27. The well ofclaim 26, wherein the nonlinear region includes at least one of atortuous region, a curvilinear region, a deviated region, an L-shapedregion, an S-shaped region, and a transition region between a horizontalregion and a vertical region.
 28. The well of claim 26, wherein the wellfurther includes a controller that is programmed to control theoperation of at least one of the rotary electric motor and the downholepositive displacement pump.
 29. The well of claim 28, wherein thecontroller is programmed to maintain a target wellbore liquid levelwithin the wellbore above the downhole positive displacement pump. 30.The well of claim 28, wherein the well further includes a sensor that isconfigured to detect a downhole process parameter.
 31. The well of claim30, wherein the downhole process parameter includes at least one of adischarge flow rate from the downhole positive displacement pump and adischarge pressure from the downhole positive displacement pump.
 32. Thewell of claim 30, wherein the controller is programmed to control arotational frequency of the rotary electric motor based, at least inpart, on the downhole process parameter.
 33. The well of claim 30,wherein the downhole positive displacement pump includes an axial pistonpump, and further wherein the controller is programmed to regulate aplate angle of a wobble plate of the axial piston pump based, at leastin part, on the downhole process parameter.
 34. The well of claim 30,wherein the downhole positive displacement pump includes a liquid inletvalve that is configured to selectively introduce the wellbore liquidinto a compression chamber of the downhole positive displacement pump,wherein the downhole process parameter is indicative of a gas lockcondition of the downhole positive displacement pump, and furtherwherein the controller is programmed to open the liquid inlet valveresponsive to the downhole process parameter indicating the gas lockcondition.
 35. The well of claim 28, wherein the controller isprogrammed to regulate a discharge flow rate from the downhole positivedisplacement pump to control a discharge pressure from the downholepositive displacement pump, and further wherein the controller isprogrammed to at least one of: (i) increase the discharge flow rate toincrease the discharge pressure; and (ii) decrease the discharge flowrate to decrease the discharge pressure.
 36. The well of claim 26,wherein the well further includes a lubricator that is in fluidcommunication with the casing conduit, wherein the downhole positivedisplacement pump and the rotary electric motor together define adownhole assembly, and further wherein the downhole assembly is sized tobe located within the lubricator.
 37. The well of claim 26, wherein thedownhole positive displacement pump includes fewer than three stages.